1. Field of the Invention
This invention relates to methods and fluids used in treating a subterranean formation. In particular, the invention relates to the preparation and use of polymer delivery systems in the form of concentrated polymer suspensions useful for creating wellbore fluids and in methods of treating subterranean formations. Also in particular, the invention relates to methods to control the stability of polymer delivery systems.
2. Description of the Related Art
Various types of fluids are used in operations related to the development and completion of wells that penetrate subterranean formations and to the production of gaseous and liquid hydrocarbons from natural reservoirs. These operations include drilling, perforating, fracturing, modifying the permeability, or controlling the production of sand or water. The fluids employed in these operations are known as drilling fluids, completion fluids, work-over fluids, packer fluids, fracturing fluids, stimulation fluids, conformance or permeability control fluids, wellbore cleanout fluids, gravel pack fluids, consolidation fluids, and the like, and are collectively referred to herein as well treatment fluids.
Water-soluble polymers are frequently used for modifying the rheology and other physical properties of well treatment fluids including viscosity, proppant suspension, and friction reduction. Water soluble polymers include guar, cellulose, and derivatives thereof and may be delivered to a work site as a hydrocarbon slurry or dry polymer.
Creating well treatment fluids often involves the steps of dispersing and hydrating polymers into a water stream. The equipment, time, and energy costs of this process are high. Hydration of polymers for oilfield applications is often a slow process requiring at least a few minutes to agitate the polymer and sophisticated water delivery procedures including a water flow path that contains different compartments. In fact, the operation often must have a specific hydration unit, such as a Precision Continuous Mixer (PCM), on top of a blending unit, such as a Programmable Optimum Density (POD) blender to provide the long hydration time required for polymer hydration.
It is desirable to have a hydration process that obtains above 80 percent final fluid viscosity in less than 1 or 1.5 minutes, but several factors including guar chemical properties, mechanical equipment limitations, and inadequate additive properties continue to hinder hydration capabilities.
Guar powders are generally obtained through a grinding process, then the powder undergoes hydration. The guar particles generally have a twisted, plate-like structure that can be observed under a microscope. Upon contact with water, the twisted structures quickly unwind into layered structures that are more flat. As these structures are intercalated by absorbing more water, they swell unevenly into larger plates wherever they contact water. With uneven swelling between the layers, and assisted by some agitation, the layers exfoliate to almost individual sheets. The final step completely dissolves the swollen plate structures into individual molecular coils. In the hydration process, the swelling and exfoliation steps occur rapidly, usually in less than 10 seconds. The exfoliated plate dissolution step is much slower, depends on the degree of agitation, and accounts for about 50-70 percent of the total time for the complete hydration process.
Typically, a smaller polymer particle has a higher ratio of surface area to contact an aqueous phase and exhibits faster hydration. However, very small guar particles do not conform exactly to this rule of thumb. Often, the dry grinding process can physically break the guar molecular chains, lowering the polymer molecular weight, and ultimately lowering the gel viscosity yield. In addition, smaller particle size grinding requires more sophisticated grinder geometry, higher energy input, more heat dissipation control, and higher costs. Furthermore, when particles are small, they tend to form fish-eyes during hydration. That is, the outermost particles agglomerate quickly and hydrate to a thick gelatinous material that encapsulates the interior particles of agglomerate and prevents water from entering into the core for further hydration. Thus, the use of finer guar particles often does not reduce the time to complete the hydration process.
Historically, oilfield polymer solutions were gelled in batch mixing processes by which dry polymer was mixed with water in tanks large enough to hold all the fluid for a wellbore treatment. These batch treatment processes had numerous limitations including bacterial decomposition and the potential for leftover fluid not used at the site. Additionally, batch mixing did not easily accommodate changes in gel concentrations or loading during the course of a treatment. Accordingly, methods have been developed to continuously mix polymer solutions at a wellsite. A successful technique must allow accurate metering of polymer material, produce hydrated polymer fluids with a minimum amount of equipment, and avoid the formation of fish-eyes when polymer particles contact water.
Continuous mix systems typically use non-aqueous slurries or dry powder systems. Non-aqueous slurries comprise dry polymer suspended in an oil solvent, often diesel fuel. Alternatively, dry systems may be used which are directly mixed with water, but the dry systems are not entirely effective and require complicated polymer hydration equipment that is disclosed in U.S. Pat. Nos. 5,190,374, 5,382,411, and 5,426,137 and United States Patent Application Publication Number 20040256106.
Friction reducers also do not resolve hydration problems effectively. Friction reducers include acrylamide homopolymer or copolymer to low viscosity fracturing fluids. SLICKWATER™ fluids, which typically contain only 0.025 to 0.2 weight percent of the friction reducer also do not work as well as hoped. Friction reducers are available commercially in oil or oil-and-water emulsions. To reduce turbulent flow in the SLICKWATER™ fluid, the friction reducer must “flip” from the emulsion to rapidly dissolve in the water, usually within several seconds or the full drag reduction will not be achieved during transit through the wellbore. Surfactants have been used in the friction reducer emulsions to shorten the flip time. Also, dilution of the friction reducer in a brine solution has been used to collapse ionic polymer chains and reduce the viscosity of the concentrated friction reducer solution. However, storage stability has been an issue because any contact with fresh water, such as condensate dripping inside a storage tank, immediately forms fisheyes, which cannot be redispersed. It should also be noted that the fisheyes form even thought the low viscosity brine-diluted polyacrylamide mixtures are clear solutions indicating no phase separation.
Although numerous continuous mix systems are now in the oilfield, none is completely satisfactory, and considerable need remains for systems with improved hydration properties. A polymer based system may be desirable. Further, it is desirable to have ways to improve the stability of crosslinked polymer based systems including systems that are concentrates and to delay or slow down bulk phase segregation during use or storage.